Bluenord ASA

OSE:BNOR

Earnings Call Transcript 2023-Q1

[Euan Shirlaw, executive]

Good morning and welcome to BlueNord's results presentation for Q1 2023.

We've had a really strong start to the year both operationally and financially, but before we go into more detail on that and given this is the first quarter since we announced our rebranding, I wanted to start by talking a little bit about BlueNord.

So our new identity is intended to be more than just a name change. It's a reflection in the growth and evolution of the company that is now BlueNord. If I look back to when I first joined in 2019, it was clear that we had a solid foundation. And yet if you fast forward to today, it's also clear that we've built upon that base and are well into our journey of delivering our potential. Taking a closer look at our new name: The term blue in BlueNord is more than just a color. It symbolizes our intent to maximize gas production, which is key to the European energy mix. Meanwhile, the Nord is a nod to both our rich history and also our strategic positioning in the Danish North Sea.

The choice to transition to BlueNord was based on aligning with who we are as a company and positioning us for the future rather than the past to deliver operationally, to deliver financially and importantly to deliver on our commitment to generate value for and return capital to our shareholders. And if we turn to the first slide of the presentation now, I'll just walk you through some of the highlights for that first quarter.

So we had strong operational performance with production of 26,600 barrels a day of oil equivalent, and that exceeded our guidance of 25,000 to 26,500 barrels a day. This strong start sets us up well for the rest of the year, and we've noted this morning that we're reviewing our guidance and expect to revise upwards for the remaining 3 quarters of the year.

The production outlook is a testament to the success of ongoing activities like the reservoir management and optimization program. For the first 2 wells on the Halfdan drilling, infill drilling, campaign, we started operations. And production is expected to start from those wells in the third quarter of this year. Coupled with Tyra coming on stream by the end of 2023 and with 7 infill wells in total to be drilled, we anticipate production will exceed 55,000 barrels a day in 2025. This production level is backed by our significant reserve and resource base with 2P and near-term 2C resources of 220 million barrels. This reflects the contingent resources that are captured by our long-term plan, which is only a subset of our 2C resource portfolio. This quarter, we also made headway on Tyra with the first gas turbine generator starting off ahead of plan, and the schedule continues to be set to deliver first gas in December 2023.

Looking outside of the DUC. We submitted a license application for the Elly and Luke discoveries; and entered a strategic partnership with Semco, adding flexibility to our long-term portfolio without requiring a significant change in either our organization or our operating model.

Turning over to the financial performance. Our operational result translated also into strong financial results. We had revenues of $221 million and EBITDA of $122 million. We generated $157 million of operational cash flow; and after accounting for investments and financing, free cash flow of $60 million. Finally, this resulted in us leaving the quarter with a strong financial position with liquidity of $529 million and no debt repayments before Tyra comes online, so in short, a strong performance that reflects the strength of our underlying portfolio.

And if we turn to the next page just to briefly revisit that portfolio. BlueNord holds a 36.8% working interest in the Danish Underground Consortium that's operated by TotalEnergies and includes substantial offshore infrastructure and direct export routes to Denmark and continental Europe. The DUC encompasses 15 fields in 4 hubs, 3 of which are currently producing; and 1 of which is under redevelopment, Tyra, and is expected to restart in December 2023. We've recently shared our long-term strategic plan for the DUC. This plan incorporates the restart of Tyra, 7 infill wells and 3 developments that will be on stream by 2029. Delivery of this plan will see BlueNord continue to strengthen its strategic position as a leading European energy producer. And with that context of European energy security, something that we're all familiar with, our strategy remains the same. We'll continue to seek to maximize our production to the extent it's economic to do so to supply Europe with the energy it needs for as long as it needs it.

And if we turn over to the next slide. 2022 is a year that really stands out for us. It was a year where our strategic importance grew significantly, where we had excellent performance at our 3 producing hubs and made significant progress in bringing Tyra back on stream. And finally, we outlined a robust activity plan for the DUC that will see us producing more than 55,000 barrels a day in 2025 and more than 40,000 barrels a day in 2030. And much of this performance reflects progress that we made against the strategic goals that we set out at the start of 2022, and we'll continue to build upon that momentum as we move into 2023. So we're delivering operationally, thanks to strong production driven by active reservoir management mitigating the natural decline. Key activities like WROM will continue through 2023. And we are pursuing short-cycle investment opportunities like the infill drilling.

We're delivering Tyra. As I mentioned, progress has been made, highlighted by today's announcement that the first GTG has been -- has started up. This keeps us on track for first gas in December 2023, but we also recognize that there is the potential for improvement in offshore productivity. Once on stream, Tyra will materially drive forward BlueNord's performance: increased production; reduced operational costs; lower emissions; and importantly, significant free cash flow generation.

We're also delivering our long-term potential. As I mentioned, we unveiled the long-term plan for the DUC last quarter. That plan, part of our substantial contingent resource portfolio, offers attractive organic upside opportunities. Beyond the DUC, we've also recently submitted the license application for Elly-Luke, showcasing our commitment to exploring opportunities for future value creation. And we'll delve into this a little bit further on the next page, but I wanted to note, before we get there, our approach to unlocking this long-term potential is very much mindful of both our capital structure but also the commitment that we've made of maximizing shareholder returns.

So as I think everybody knows, our focus is on maximizing shareholder value and progressing the activities that are supportive of that goal. A key part of this is establishing a sustainable and substantial dividend profile. Our robust capital allocation framework is designed to ensure that, that dividend is reflective of our cash generation potential. And within this framework, to emphasize the point, distributions to shareholders really are priority #1. I've already touched on some of the organic growth opportunities that we have. And I'll let Marianne and Cathrine delve into that a little bit deeper, but what I did want to say is that it's always worth bearing in mind that any future investment decisions that we take will always be evaluated based on their potential impact on our overall distribution capacity both in terms of timing and quantum.

Finally, as we step into our new identity as BlueNord, we also recognize the role that we have to play balancing the dual objectives of energy security and the energy transition. We are committed to operating with the lowest possible emissions intensity and reducing our carbon footprint. This is our way of supporting a future where we both meet the energy demands of today and safeguard the environment for the future.

And with that, I'll hand over to Marianne to walk through the operational performance in Tyra.

Thank you.

[Marianne Eide, executive]

Thank you, Euan. And good morning, everyone.

So on the operational performance. We are continuing the trend with good performance from the last year. Q1 production was 26,600 barrels of oil equivalent a day, which is just above the upper guidance. As you can see from the plot, we are keeping production flat from 2001 (sic) [ 2021 ] through 2022 and now Q1 2023. We are able to beat the natural reservoir decline with a high level of well activity, and in the first quarter, we have already done 20 well interventions. We have been particularly successful with the restimulations of wells on the down field. And this has also increased our gas production share to 25%. Halfdan and Gorm have both produced according to plan, and overall operational efficiency have also been high at 89%.

Based on the fact that Q1 production was above the guidance and caused by better underlying reservoir performance than expected, we are now reviewing field performance, plans for shutdowns, timing of start-up of new wells in detail to prepare a new guidance, which will be an upward guidance. However, we do not expect to be able to maintain the Q1 production level on short term. We have planned shutdowns in both Q2 and Q3, and the shutdown for the Halfdan reroute project is imminent and is expected to last for 2 weeks. This project will eliminate routine flaring and which is a fantastic step forward for the DUC. We have also got a regular shutdown for maintenance on Halfdan B in August. And in addition to this, we will need to shut-in nearby wells when drilling the Halfdan infills.

Moving on to the infill drilling. We are now putting the long-term plan into action with the drilling of 2 infill wells this year. So far, we have used the jack-up rig Shelf Drilling Winner for well intervention activities. We will still -- continuing with the well activities from stimulation vessels and from the Noble Reacher. And in the Winner rig sequence, some time has also been allocated for critical well activities between the different well -- infill wells. The rig is now on location. And we have started slot recovery work, and [ spud ] of the first well is expected within the next month.

The 2 Halfdan wells will add around 3 million barrels of oil equivalent of reserves, with 50-50 oil and gas split. The net Noreco cost for the 2 wells is around $39 million, which also includes plugging of 2 old wells to free up the well slots. We will get a nice initial boost when the wells come on stream with around 3,000 barrels of oil equivalents per day but with a relatively fast decline. The wells will be put on production as soon as drilling is completed; and expected onstream in, respectively, third and fourth quarter this year. The full effect of the wells will be seen on the production figures mainly for next year because we will have a relatively slow ramp-up of the wells to ensure that we maintain the maximum production potential long term.

Around year-end, we expect to sanction further 3 wells: 1 near-field low-risk exploration well from the Harald field, 1 of the Tyra satellites which is located 84 kilometers north of Tyra, close to the Norwegian border; and further 2 infill wells on Halfdan, in the Ekofisk formation. The drilling sequence on the Shelf Drilling Winner is dynamic. And we will make optimization as we get new insight from technical studies and production history as well to make sure that we're using the rig slots in the very best way. The 2 last well slots are still subject to optimization and final decision, so we kept a generic name for these. We have secured the Shelf Drilling Winner at a very favorable day rate until the beginning of 2025.

These infill drilling projects all yield a good internal rate of return, depending on oil and gas prices, of course. We reported an internal rate of return for the first 2 Halfdan infill wells of more than 200% back in December last year, but then the gas price was very high. Using more conservative price assumptions for oil and gas, we still [indiscernible] for the portfolio of infill wells.

Moving on to the Tyra project. The Tyra development is of strategic importance and will provide necessary gas to Denmark and Europe and will transform our business in the DUC. We will be able to unlock significant volumes from Tyra and the satellites with modern and efficient processing facilities. The CO2 intensity from the BlueNord operations will reduce with around 30%. We will also almost double the BlueNord production and expect to produce 55,000 barrels of oil equivalents per day net in 2025 with a gas share of 45%. The increased production from Tyra also means that we will reduce our unit operating cost significantly to just below $13 per barrel.

The hook-up and commissioning activity level on Tyra will reach a maximum now in May and stay at max through Q2 and Q3 with a dedicated offshore construction workforce of more than 300 people. On top of this, we have commissioning and support personnel like catering, scaffolding, safety, et cetera. And what I would say is that, last year, we saw access to offshore workers as a key risk to delivery of this project and delivery of first gas. So far, we have been able to fill all available positions.

The Tyra East complex is the heart of the Tyra redevelopment and consists of 5 platforms linked with bridges. There is one riser platform, where production from the satellite fields are coming in and where produced gas is exported to shore and condensate is exported to the Gorm complex. We have made good progress with the riser tie-ins on this riser platform. We then have 2 wellhead platforms where we are now installing refurbished wellheads for each of the wells that have been suspended. And the well reinstatement work has gone very smoothly. There was a bit of a slow start with lower offshore productivity than planned, but we are now making good progress. What is essential for first gas is the riser connections, where we have completed [ Dan and Gorm ]. The key one remaining is the gas export riser.

The key platform for reaching first gas is the TEG, Tyra East G. This is where all processing of the gas produced from the Tyra East wells and the satellites field will be done, reaching export specification on both gas and condensate. What is key to reach first gas is to have power available to run the process. We have 3 gas turbine power generators, each generating 35 megawatts. We need 2 to run the entire process, so we have 1 spare because this is critical equipment. This power generation is required to run the process and also to do the commissioning and start-up work. And in order to run these giant compressors, you need sea water cooling, and even more importantly, you need the firewater system to be in full operation. Without this power generation, we will not be able to start up and test the rest of the process equipment. We have had some issues with cranes, leading to lower offshore productivity and thus had -- this has led to some delay [indiscernible] pleased to announce that, the day before yesterday, we actually started up the first gas turbine generator. This happened ahead of schedule, so a good indication that we are on track despite some issues with cranes and offshore productivity.

On Tyra West, we are behind schedule because a decision was made to move a key part of the Tyra West crane to the TEG crane which was more important. The Tyra West crane should now be up and running, and key scope is being completed. The most significant is the Valdemar riser tie-in. And Tyra West is not on a critical path for first gas.

Looking at the completed milestones, we have achieved a lot this year. We have connected the risers to Harald and Dan. We have completed the first phase of Tyra East well reinstatement. Recently we have connected the firewater system on TEG, which is provided from the living quarter platform TEH. And again, 2 days ago, we started the first gas turbine generators. And I would say that, the TotalEnergies team, they have been doing a brilliant job getting to this milestone. You will notice from the upcoming milestones that we still have a first G2G (sic) [ GTG ] running-on-diesel milestone to complete. Even if we did a successful test, we do not have all the systems in place to run it over a longer period with full load. For instance, we need the sea water lift pumps to be operational to ensure that we have the necessary cooling.

We expect these milestones to be met during the summer. And next, into the autumn, is completion of all leak testing before we are ready to take gas from Dan into the system and then to run the gas export compressor and export the first gas from the Tyra facilities. On a P50 basis, we expect to reach first gas export in December, with plateau production reached during the summer. Gas from Harald will be the first gas produced from the Tyra fields to be exported.

There is no change to the overall budget for Tyra, so we are continuing to draw down on the budget, with now $150 million remaining to first gas. And we then add another $90 million after first gas, so ending up with USD 240 million. [ No change ] to the range to first gas. The TotalEnergies team recently confirmed they are still working towards the P50 target with first gas in December, but there is still remaining uncertainty with respect to delivery of first gas and completion of the project. I would say that we have 2 risk areas remaining: offshore productivity, which could be impacted by downtime of key equipment like we have seen [ on the crane ] but which is, hopefully, behind us. We could also see and have unexpected quality issues with the process equipment delivered from the yard, which could be uncovered during the commissioning process that we are embarking on right now.

As mentioned earlier, getting Tyra on stream and at plateau production will transform our business. And our lifting costs [indiscernible] 2025. We are expecting to see a small reduction in absolute OpEx between '23 and '25. We have a very high level of activity in '23 and we are still catching up on well interventions after some very quiet years. The most significant driver for the unit lifting costs is obviously increasing our production [indiscernible] Tyra is on stream.

So with this, I'm handing over to Cathrine, our EVP, ESG and Investor Relations. And she will talk you through ESG and also our potential future growth.

[Cathrine Torgersen, executive]

Thank you, Marianne.

I will mainly focus this section on energy security. However, I would like to highlight a few ESG and transparency improvements we made during Q1.

6 weeks ago, we announced a name change to BlueNord. And alongside that change, we also published a completely new annual report. Throughout the report, you will see a lot of focus has gone into raising our reporting standards on ESG. There is an overall improved transparency of emissions and risks and we have also improved several internal routines. We have also reported against TCFD for the first time. And our preparations for the upcoming implementation of the European ESRS is also reflected throughout the sustainability section.

With new legislation, we took measures to be aligned with the Norwegian Transparency Act and the equality and anti-discrimination act. We're also measuring ourselves against a diversity and inclusion index for the first time. On governance, we have improved the risk management framework and now has frequent monitoring in place. We also decided to disclose separate subcommittee reports in order to increase the transparency of the committees' mandates and their work.

We state that our ambition is to provide energy for Europe today, tomorrow and for our net zero future; and I would like to explain what we mean by that. The energy transition and the energy security may sound like somewhat conflicting objectives. However, today, we all need to accept that both must happen at the same time. And both are equally important both today and also longer term. We have shown our commitment to operate with the lowest possible emissions intensity and materially reduce our carbon footprint. We achieve this naturally by delivering Tyra II, which is a high-tech and efficient production facility, but we also achieve this by applying emissions reduction initiatives across the portfolio, all the way from the Halfdan reroute, to applying new technologies to better monitor and detect emissions. We have also dedicated resources to investigate the longer-term potential of CCS both offshore through Bifrost and onshore through CarbonCuts. And while we keep this focus, we also recognize that we're still in a very difficult situation when it comes to near-, medium- and longer-term energy supply.

Energy security is one of the biggest challenges of today. And it is a key objective for BlueNord to supply Denmark and also Europe with the energy it needs, as long as it is needed. The energy market is global. However, we also tend to apply geographical boundaries on our countries or regions, reflecting energy transition targets or politics. This is especially true for the gas markets. If, for example, one highly developed country reduces materially its production of gas to lower its emissions, the need of that energy source will most likely be met by less clean and safe alternatives.

In Europe, this winter, we did manage to get past the period with almost full storages. It's important, though, to also recognize that this was probably a result of several factors that maybe will not be as favorable the next coming winter seasons. First of all, we started the season with relatively full storages. Those storages also included volumes from Russia. Secondly, the winter in Europe was record warm this year. We also saw significant reduction in industrial activity in Europe which is not sustainable over time. And then we switched to alternatives and fired up coal plants again. We also saw a delay in the Chinese reopening post COVID. And we, by that, have access to relatively cheap imported LNG volumes. China's appetite for LNG is probably going to return this year. And the International Energy Agency is forecasting a 15% growth in imported LNG volumes to China for this year. And remember that LNG is gas being liquefied at extremely low temperatures then transported for very long distances before it's finally reheated, all in all a pretty energy-intensive value chain, so the environmental footprint of a unit of imported LNG is difficult to defend when you compare it to [ pipe gas ] being produced within Europe.

Based on everything I just mentioned, BlueNord is therefore committed to maximizing its gas production in Denmark. And we estimate our gas volumes to grow by 250% following Tyra and the planned infill wells. That leads me to the next slide. I'm not going to spend too much time on the infill wells, as these have just been covered by Marianne in detail. I will, however, emphasize that in the long-term plan we also have 3 very attractive identified low-cost projects which will help BlueNord sustain a high level of production long into the future.

The infill wells together with the currently producing assets and Tyra brings us up to above 55,000 barrels per day in 2025. And following the 3 projects Valdemar Bo South, Adda and Halfdan North which I will go [indiscernible] our net productions [indiscernible] per day in 2030. The 3 projects mentioned will add approximately 43 million barrels, based on the latest 2C figures. Valdemar Bo South and Halfdan North are mainly oil volumes, while the largest project, which is Adda, is heavily weighted towards [ gas ]. They all have unit CapEx below $15 per barrel and they are all projects with relatively simple production infrastructure needed. Production from the 2 first projects can be tied back to Tyra II, which is a great way of getting more value from the new and state-of-the-art facility which Tyra is and ensuring that the process capacity is fully utilized.

BlueNord expects the 3 projects to start production from 2026, 2027 and 2029, with Valdemar Bo South being the first to be FID-ed next year.

On the next slide, you will see the forecasted production growth over a 10-year period. Dark blue is the current production we have from Halfdan, Gorm and Dan. Light green is the base production we will see come from Tyra, and the turquoise represent the in-plan projects I just mentioned. It's maybe difficult to see if you use a small screen, but the infill volumes are just about noticeable this year when we see the first volumes from the infill wells coming in. It's important to note that the forecasted production on this page does not account for the full 2C potential we have in the current portfolio. It only represents a portion of these, and as such, the real potential may be much higher than what we're currently looking at.

And on the final slide, I would like to touch upon the recent news we announced, the Elly-Luke application and also the strategic partnership we entered into with Semco Maritime. It's not a coincidence that these were announced at the same time, as they're somewhat connected. The Elly-Luke application is very exciting for us as a company and has involved most parts of our organization. This is the first tangible step BlueNord is taking outside of the DUC, and it is further emphasizing the role we intend to play in Denmark and in supporting energy security to Europe.

These are discovered resources. Most of it is gas. And the discovery is currently believed to have the potential to deliver 5 billion cubic meters of natural gas. The first step now is the upcoming mini licensing round which has an expected award of license late this year. Then we will carry out a work program to assess if the discovery is commercial prior to any investment decisions being taken and also to ensure that the development and the actual production is done within as low environmental footprint possible. We will need to -- it will need to be a top priority in order for Elly-Luke to make sense.

It's also very important to note that the development of Elly-Luke will not jeopardize the North Sea agreement which puts an end to oil and gas production in Denmark in 2050. The production lifetime is approximately 15 years long. And we strongly believe that the successful Elly-Luke will mean that Denmark is able to deliver necessary and stable gas to the EU which is produced not only safely but also with a low environmental footprint.

And as we're considering the potential which lays outside of the DUC, the partnership with Semco Maritime is very important to us. Semco has a long and well-recognized history as an international contractor. Together with Semco's operational expertise, we have established a structure which enables us to pursue opportunities in Denmark in a way that aligns with our current internal capabilities. The partnership will allow us to jointly identify, explore and also investigate the oil and gas space; and this is a tangible and important step for BlueNord.

And with that, I will leave the word over to Jacqueline, who will take you through the financial results.

[Jacqueline Lindmark Boye, executive]

Thank you, Cathrine.

So 2023, on the financial side, has started well with a continuation of the excellent underlying operating performance we saw in 2022. Commodity prices have softened since the fourth quarter of last year, but both oil and gas prices remain relatively high. And with regards to gas, we have been able to take advantage of some positive hedging opportunities. In addition, our liftings of oil for this quarter have also been up compared with the previous quarter. This combined has enabled us to maintain a solid revenue result for the first quarter of $221 million compared to $230 million in Q4 2022.

Our operating cost level continues to include activities related to well recovery and optimization, which is supporting the solid production performance which Marianne spoke about earlier. A slight reduction in our OpEx since the fourth quarter last year is primarily due to transportation which was unusually high in Q4. And that was due to a one-off cancellation fee as well as some year-to-date true-ups, so we're now on a more normal level, if you like. As a result of the above, the overall contribution margin remained significantly positive, as you can see on the chart here on the slide.

Bringing this together, we report an EBITDA of $122 million this quarter, comparing with $140 million in the previous quarter.

Turning to the summary income statement, you can see the full earnings position. I've already highlighted the revenue performance and some of the key OpEx drivers, so the main points to draw out here are, in particular, on the other production expenses. You can see there is an increase, but this is just mainly a result of the unwind in our under-lift position. But I think, the other point to note here, you can see the tax figure of an expense of $32 million in this quarter; and that does reflect our underlying earnings performance. And whilst it is higher than the last quarter, that was as a result of a one-off adjustment in our deferred tax relating to a foreign exchange adjustment, so actually, when you exclude this, it's quite consistent and in line with our expected effective tax rate.

If we have a quick look at the balance sheet summary. This highlights that spend continues on Tyra redevelopment in particular, when you look at the additions in property, plant and equipment. Also in line with our results, you can see deferred tax is starting to decrease. And this is, of course, as losses are utilized.

Now in terms of the tax payable position, I'd like to highlight that you can see there is a balance of $251 million at the end of this quarter. This includes our expected payment of Chapter 2 taxes for 2022 as well as the year-to-date of 2023 thus far. It also includes our expected payment for the solidarity contribution for 2023. As you may recall from the previous quarter, the solidarity contribution is based on the existing hydrocarbon tax regime, so we don't expect our marginal tax rate to increase. So of this balance of $251 million, $231 million is cash tax payable later in 2023. And then a portion of it is also into -- payment in 2024.

Turning to cash. I'm pleased to report a positive cash generation of $147 million before investments. We added a net $60 million free cash flow to our liquidity position, so we remain fully funded in the outlook for the Tyra -- until the Tyra redevelopment project is complete. So we have a closing liquidity position of $529 million.

When you look at our operating cash flow. There are a number of factors influencing the positive result when you compare to last quarter. This time, we are benefiting from a working capital adjustment with positive cash receipts from oil and gas and, of course, some of the unwind of the oil under-lift which I mentioned earlier as well. Our investing cash flows are relatively consistent quarter-on-quarter. Primarily the Tyra redevelopment project is the spend in capital. And you can also see the final consideration paid of $25 million to Shell. This was in relation to the 2019 acquisition of their Danish upstream assets, and it's the final payment in that respect.

Turning to look at our capital structure. You can see this remains robust and fully funded to deliver Tyra II. We have a stable balance sheet with no principal maturities prior to Tyra's first gas. And you can see the net debt at the end of the quarter is $860 million. This shows a decrease from $939 million at the end of the last quarter, reflecting the payment I referred to earlier. And of course, the additional free cash flow of $60 million is also added. This chart, just to note, also reflects the completion, of course, of the NOR13 restructuring to NOR15 which we talked about previously; and this was finalized in January.

So lastly, I'd like to talk a little bit about the commodity price environment as it relates to BlueNord. As we've spoken about before, the primary purpose of our price hedging is to provide visibility over future cash flow. And we will continue to apply an approach where we add volumes where it makes sense to do so. Our oil hedging remains consistent in 2023, with some hedging being added to the second half of this year. Regarding gas, we have hedged some additional volumes throughout the remainder of 2023, out to Q3 2024.

We continue to add hedges when it looks attractive to do so and within our policy framework, of course, so you can see from the chart here the average hedge price for oil is steadily increasing from $51.7 per barrel in Q2 '23 to $74.7 per barrel in Q2 2025. The average hedge price for gas remains above the current market spot and forward prices. In summary, you can see in the chart summer of 2023 is at an average of EUR 121.2 per megawatt hour. The winter of '23 and '24 is at an average of EUR 140.7 per megawatt hour. And the summer of '24 has some initial hedging at EUR 57 per megawatt hour, so aligned with our production guidance, we are currently hedged at around 60% on oil and 38% on gas.

This hedging approach has supported our balance sheet and capital structure through a continued uncertain price environment, so it does help to bring a level of certainty to the funding position.

So in summary. 2023 has started well with continued positive earnings resulting in strong cash flows that support our balance sheet. This is underpinned by a robust capital structure and continues to enable delivery of our operational and financial goals.

And on that note, I'll turn back to Euan for closing remarks.

[Euan Shirlaw, executive]

Thank you, Jacqueline.

So before we open up for questions, now that you've heard where we are today and also some of the key catalysts we have coming up, I wanted to emphasize just a couple of points from today's discussion. Firstly, the business is performing very strongly operationally and financially. We will carry this momentum into 2023 and beyond. Secondly, we have a high-quality asset base supported by a material portfolio of reserves and resources, so there's plenty more for us to do. And as we go about delivering our long-term potential, we will always be guided by what is our primary focus of maximizing shareholder returns.

So thank you again for joining today. And let's pause for 30 seconds to allow any additional questions to be submitted, and then we'll come back to answer them.

Thank you.

[Cathrine Torgersen, executive]

Okay. So the first question is for Marianne. By how much do you expect to revise production guidance?

[Marianne Eide, executive]

So I will -- we're still doing the technical work to really understand the performance of each of the fields and also what is -- the more detailed plans for shutdowns, so I don't have an estimate for how much we will increase the guidance.

[Cathrine Torgersen, executive]

And then Jacqueline, what should we expect as long-term OpEx in absolute U.S. dollars after Tyra first gas?

[Jacqueline Lindmark Boye, executive]

Of course, it does depend on the level of activity, in particular the well activity, in the future, but as we've presented in the slides, the 2025 year of USD 250 million is a good indicative level. But this is where we do have some reduced well activity at that point in time but is consistent with the production profile that we also presented.

[Cathrine Torgersen, executive]

Thank you. Marianne again: When do you expect to revise your Q2-to-Q4 2023 production guidance?

[Marianne Eide, executive]

So before publishing a new guidance, we would like to have completed the Halfdan reroute work and to see that we have stable production again, so where -- we expect to announce a new guidance in the beginning of June.

[Cathrine Torgersen, executive]

And then Euan, how should we think around dividend in the long term as a percentage of cash flow, earnings per share or other? Should we expect first dividend announced during 2024?

[Euan Shirlaw, executive]

So we haven't provided any detailed dividend guidance to the market yet, but I think you can expect us to do so later in 2023. What I can say, though, is when you look at the capital allocation framework that we have, one of the first steps of that is making sure that we're maximizing the cash flow generation from our existing assets and then thinking about how we allocate that cash flow. So with that in mind, I think what I can say when we look at the methodology for setting the dividend: It seems as though having it linked to cash flow would make more sense than having it less -- linked to earnings, which are obviously much more volatile, particularly when you account for the fact that we have a tax loss position.

[Cathrine Torgersen, executive]

Thank you. And the next question is also closely linked to this. How should we look at capital allocation post 2023?

[Euan Shirlaw, executive]

So from a capital allocation perspective, it's going to be defined by really what we have on the framework, so it's a combination of shareholder returns, which is going to be defined by that dividend policy; deleveraging, which is happening naturally at the moment, anyway; and then looking at the organic growth opportunities that we have. So I don't think we can be any more specific now in terms of what the sort of tangible percentages are that go alongside it, but the main message is very much that it will be shareholder returns that in the first instance are prioritized.

[Cathrine Torgersen, executive]

And then Euan again. Should we expect to see any voluntary repayments of the RBL in '23 and '24?

[Euan Shirlaw, executive]

So as it stands at the moment, we are consistently building up cash on our balance sheet, so I think it's not unreasonable to expect us to have another voluntary repayment under the RBL, but as it stands at the moment from a debt drawn perspective, we benefit from the fact that we have interest rate hedging in place, so it's significantly cheaper to borrow that money versus any other of the sources that we might have available.

[Cathrine Torgersen, executive]

And then Jacqueline, regarding OpEx, what are the drivers for increased direct field OpEx and reduced transportation OpEx?

[Jacqueline Lindmark Boye, executive]

Yes. The direct field OpEx needs to be looked in conjunction with production G&A. There's been a change in the cost allocation methodology with the operator at the DUC, so you will actually see a reduction in production G&A compared to the previous quarter offsetting part of that increase in direct field OpEx. Transportation has gone down. And I think I mentioned there was in Q4 -- and it was higher than you would expect because of some one-off items, so the level that we have now is more at the normalized rate, where you exclude the cancellation fee and the true-up on year-to-date in 2022.

[Euan Shirlaw, executive]

I think one thing just to reemphasize on the direct field OpEx is that a big driver of it being higher is the production-supporting activities that we have on WROM. So you obviously mentioned that, Jacqueline, but just to emphasize again, that's the key driver. And so long as your contribution margin is positive, as we've shown that it is, it very much makes sense to do those activities to keep your production high.

[Jacqueline Lindmark Boye, executive]

Yes.

[Cathrine Torgersen, executive]

And then Jacqueline again. Does the long-term $13 per barrel include all direct field OpEx, transportation OpEx and production G&A OpEx?

[Jacqueline Lindmark Boye, executive]

It includes the direct field OpEx and the production G&A but not the transportation costs, so it's really the lifting costs, if you like, out in the DUC.

[Euan Shirlaw, executive]

If you correspond that to what we've communicated previously, which was direct lifting costs below $13 per barrel, this is actually a slightly further step than that because this is direct lifting plus production and -- plus production G&A being less than $13 per barrel.

[Jacqueline Lindmark Boye, executive]

Yes.

[Cathrine Torgersen, executive]

And then the final question. Marianne, is Elly-Luke a tieback candidate to Tyra?

[Marianne Eide, executive]

Yes. So a tieback to Tyra is one of several concepts that we will evaluate.

[Cathrine Torgersen, executive]

Great. I think that concludes the Q&A session. Thank you all for listening in.